In geotechnical engineering various types of fluids are needed. These fluids include, but are not limited to, well bore treatment fluids, kill fluids, packer fluids, and thermal insulating fluids. For example, when drilling an oil or gas well, drilling fluid is used to aid the drilling of boreholes into the earth. Drilling fluids are also used for much simpler boreholes, such as water wells. Liquid drilling fluid is often called drilling mud. The three main categories of drilling fluids are water-based fluids (which can be dispersed and non-dispersed), non-aqueous fluids, often called oil-based mud, and gaseous drilling fluid, in which a wide range of gases can be used.
The main functions of drilling fluids include providing hydrostatic pressure to prevent formation fluids from entering into the well bore, keeping the drill bit cool and clean during drilling, carrying out drill cuttings, and suspending the drill cuttings while drilling is paused and when the drilling assembly is brought in and out of the hole. The drilling fluid used for a particular job is selected to avoid formation damage and to limit corrosion.
Agents for lubrication are often included in the fluid as well as weighting materials in order to achieve a density such that the hydraulic pressure of the fluid is typically greater than the surrounding pressure in the well bore. Furthermore, when fluids are used during drilling, the fluid often contains drilling fines, such as shale and sandstone fines. During the drilling operations and afterwards, a filter cake seals the formation surface of the well bore so that the well bore can be completely formed without any leakage from the formation surface into the well bore and/or without any leakage of the drilling fluids into the formation surface.
A well kill is the operation of placing a column of heavy fluid into a well bore in order to prevent the flow of reservoir fluids without the need for pressure control equipment at the surface. It works on the principle that the weight of the fluid, i.e., the “kill fluid” or “kill mud,” will be enough to suppress the pressure of the formation fluids.
Packing and insulating fluids are also often used in subterranean operations. These fluids are usually placed into an annulus between a first tubing and a second tubing or the walls of a well bore. The fluid acts to insulate a first fluid (e.g., a hydrocarbon fluid) that may be located within the first tubing from the environment surrounding the first tubing or the second tubing to enable optimum recovery of the hydrocarbon fluid. For instance, if the surrounding environment is very cold, the fluid protects the first fluid in the first tubing from the environment so that it efficiently flows through the production tubing, e.g., the first tubing, to other facilities. This is desirable because heat transfer can cause problems such as the precipitation of heavier hydrocarbons, severe reductions in flow rate, and in some cases, casing collapse. Additionally, when used in packer applications, a required amount of hydrostatic head pressure is needed. Thus, higher density fluids are often used to provide the requisite hydrostatic force.
Once a drilling operation has been completed, the well is prepared for the completion operations whereby the fluids used for drilling are typically displaced by a completion fluid. Completion fluids are usually formulated to the same density as the fluid used to drill the well in order to retain the hydraulic pressure on the well bore.
Cesium formate is often used in wellbore fluids because it is extremely soluble in water. Nonetheless, cesium formate is expensive, can cause corrosion problems such as hydrogen stress corrosion cracking and hydrogen embrittlement, and is not always sufficient to weight up the fluid. Localized corrosion, pitting and stress corrosion cracking are particularly problematic and related to a high risk of unpredictable and rapid failure of metal integrity. Pitting corrosion and stress corrosion cracking are common and frequently occur in well tubulars constructed from so-called corrosion resistant alloys. Corrosion inhibitors have little or no effect and can actually initiate corrosion. Hydrogen embrittlement is a brittle mechanical fracture of high-strength steels caused when atomic hydrogen dissolves in the crystal structure of a metal rather than forming hydrogen gas. It typically occurs in corrosive environments under constant tensile stress, similar to hydrogen stress corrosion cracking. The most common form is sulphide stress cracking, which occurs when stressed metal is exposed to water containing hydrogen sulphide or other sulphur compounds, generally under aerobic conditions.